U.S. patent number 8,908,343 [Application Number 13/285,886] was granted by the patent office on 2014-12-09 for system for electric distribution system protection and control and method of assembling the same.
This patent grant is currently assigned to General Electric Company. The grantee listed for this patent is Amol Rajaram Kolwalkar, Yan Pan, Swakshar Ray, Michael Reichard, Wei Ren, Reigh Allen Walling. Invention is credited to Amol Rajaram Kolwalkar, Yan Pan, Swakshar Ray, Michael Reichard, Wei Ren, Reigh Allen Walling.
United States Patent |
8,908,343 |
Pan , et al. |
December 9, 2014 |
System for electric distribution system protection and control and
method of assembling the same
Abstract
An electric distribution system includes at least one feeder and
a protection and control system. The feeder includes at least one
segment including a first end and an opposing second end. The
protection and control system includes a protective device and an
electric current measuring device coupled to the segment proximate
each end. The system further includes at least one processor
coupled in communication with the electric current measuring
devices. The at least one processor is programmed to determine a
difference between a synchronized first electric current measured
proximate the first end and a synchronized second electric current
measured proximate the opposing second end and determine a
switching condition of the protective devices as a function of the
difference between the synchronized first and second electric
currents.
Inventors: |
Pan; Yan (Niskayna, NY),
Ren; Wei (Niskayuna, NY), Ray; Swakshar (Guilderland,
NY), Reichard; Michael (Schenectady, NY), Kolwalkar; Amol
Rajaram (Bangalore, IN), Walling; Reigh Allen
(Clifton Park, NY) |
Applicant: |
Name |
City |
State |
Country |
Type |
Pan; Yan
Ren; Wei
Ray; Swakshar
Reichard; Michael
Kolwalkar; Amol Rajaram
Walling; Reigh Allen |
Niskayna
Niskayuna
Guilderland
Schenectady
Bangalore
Clifton Park |
NY
NY
NY
NY
N/A
NY |
US
US
US
US
IN
US |
|
|
Assignee: |
General Electric Company
(Niskayuna, NY)
|
Family
ID: |
48172185 |
Appl.
No.: |
13/285,886 |
Filed: |
October 31, 2011 |
Prior Publication Data
|
|
|
|
Document
Identifier |
Publication Date |
|
US 20130107407 A1 |
May 2, 2013 |
|
Current U.S.
Class: |
361/84;
361/93.1 |
Current CPC
Class: |
H02H
3/305 (20130101) |
Current International
Class: |
H02H
3/00 (20060101); H02H 9/02 (20060101); H02H
3/08 (20060101) |
Field of
Search: |
;361/84 |
References Cited
[Referenced By]
U.S. Patent Documents
Other References
Y Pan, et al, Impact of Inverter Interfaced Distributed Generation
on Overcurrent Protection in Distribution Systems, 6 pages. cited
by applicant.
|
Primary Examiner: Patel; Dharti
Attorney, Agent or Firm: Joshi; Nitin N.
Claims
What is claimed is:
1. An electric distribution system comprising: at least one feeder
comprising at least one segment comprising a first end and an
opposing second end; and a protection and control system
comprising: at least one protective device coupled to said at least
one segment proximate each of said first end and said opposing
second end; at least one electric current measuring device coupled
to said at least one segment proximate each of said first end and
said opposing second end; and at least one processor coupled in
communication with each of said electric current measuring devices,
said processor programmed to: determine a difference between a
synchronized first electric current measured proximate said first
end and a synchronized second electric current measured proximate
said opposing second end; and determine a switching condition of
said protective devices as a function of the difference between the
first and second synchronized electric currents.
2. An electric distribution system in accordance with claim 1,
further comprising at least one distributed generation device
coupled to said at least one feeder.
3. An electric distribution system in accordance with claim 1,
wherein said at least one processor comprises at least one of: a
centralized controller; or a plurality of distributed
controllers.
4. An electric distribution system in accordance with claim 1,
wherein said at least one processor is further programmed to:
determine the first electric current flowing into said at least one
segment at said first end; determine the second electric current
flowing out of said at least one segment at said second end; and
determine a location of an electrical fault as a function of the
difference between the first and second electric currents.
5. An electric distribution system in accordance with claim 1,
wherein said at least one processor is further programmed to
determine a location of an electrical fault as a function of a
difference between the first and the second electric currents of
each segment of a plurality of segments.
6. An electric distribution system in accordance with claim 1,
wherein said at least one processor is further programmed to
determine the switching condition of said plurality of protective
devices as a function of a difference between the first and the
second electric currents of each segment of a plurality of
segments.
7. An electric distribution system in accordance with claim 1,
wherein said protection and control system comprises a plurality of
protection zones, wherein each said protective zone is defined by
said first end and said opposing second end of each at least one
segment.
8. An electric distribution system in accordance with claim 1,
wherein said protection and control system is configured to
facilitate bi-directional fault current sensing proximate each of
said first end and said opposing second end.
9. A protection system for an electric distribution system, the
electric distribution system includes at least one feeder that
includes at least one segment at least partially defined by a first
end and an opposing second end, and at least one distributed
generation (DG) device coupled to the electric distribution system,
said protection system comprising: at least one protective device
coupled to the at least one segment proximate each of the first end
and the opposing second end; at least one electric current
measuring device coupled to the at least one segment proximate each
of the first end and the opposing second end; and at least one
processor coupled in communication with each of said electric
current measuring devices, said processor programmed to: determine
a difference between a synchronized first electric current measured
proximate said first end and a synchronized second electric current
measured proximate said opposing second end; and determine a
switching condition of said protective devices as a function of the
difference between the synchronized first and second electric
currents.
10. A protection system for an electric distribution system in
accordance with claim 9, wherein said at least one processor
comprises at least one of: a centralized controller; or a plurality
of distributed controllers.
11. A protection system for an electric distribution system in
accordance with claim 9, wherein said at least one processor is
further programmed to: determine the first electric current flowing
into the at least one segment at the first end; determine the
second electric current flowing out of the at least one segment at
the second end; and determine a location of an electrical fault as
a function of the difference between the first and second electric
currents.
12. A protection system for an electric distribution system in
accordance with claim 9, wherein said at least one processor is
further programmed to determine a location of an electrical fault
as a function of a difference between the first and the second
electric currents of each segment of a plurality of segments.
13. A protection system for an electric distribution system in
accordance with claim 9, wherein said at least one processor is
further programmed to determine the switching condition of said
plurality of protective devices as a function of a difference
between the first and the second electric currents of each segment
of a plurality of segments.
14. A protection system for an electric distribution system in
accordance with claim 9, wherein said protection system comprises a
plurality of protection zones, wherein each said protective zone is
defined by the first end and the opposing second end of each
segment of a plurality of segments.
15. A protection system for an electric distribution system in
accordance with claim 9, wherein said protection system is
configured to facilitate bi-directional fault current sensing
proximate each of the first end and the opposing second end.
16. A method of assembling an electric distribution system, said
method comprising: providing at least one feeder including at least
one segment, the at least one segment includes a first end and an
opposing second end; coupling at least one protective device to the
at least one segment proximate each of the first end and the
opposing second end; coupling at least one electric current
measuring device to the at least one segment proximate each of the
first end and the opposing second end; coupling a protection and
control system in communication with the electric current measuring
devices; configuring the protection and control system to determine
a difference between a synchronized first electric current measured
proximate the first end and a synchronized second electric current
measured proximate the opposing second end; and configuring the
protection and control system to determine a switching condition of
the protective devices as a function of the difference between the
synchronized first and second electric currents.
Description
BACKGROUND OF THE INVENTION
The embodiments described herein relate generally to electric
distribution systems and, more particularly, to protection systems
for electric distribution systems.
Known electric power grids typically include power generation
plants, transmission and distribution lines, transformers, and
other devices that facilitate electric power transmission, and
power delivery. After electric power is generated in the generating
plants, it is transmitted for extended distances through the high
voltage transmission lines to subtransmission/distribution
substations. Transmission lines usually operate at voltage levels
between approximately 115 kilovolts (kV) and approximately 765 kV.
At the subtransmission/distribution substations, transformers
reduce the high voltage at which the power has been transmitted to
sub-transmission voltage levels that range from approximately 46 kV
to approximately 69 kV, or to distribution voltage levels that
range from approximately 12 kV to approximately 34.5 kV. Power is
then transmitted through a feeder to an end customer through an
electric distribution system, and before it reaches the end
customer, the voltage is decreased to approximately 120V/240V by a
distribution transformer.
Most known electric distribution systems include a plurality of
feeders coupled to the substation transformer. The electric
distribution systems may also include at least one capacitor bank,
at least one voltage regulator, and at least one distributed
generation (DG) device, e.g., a diesel generator and a photovoltaic
source. The feeder is divided into smaller units via bus-bars,
disconnect switches, reclosers, sectionalizers, and fuses, wherein
such smaller units are referred to as segments. Each segment may
have any number of DG devices coupled thereto.
Therefore, typically, most known electric distribution systems
include a plurality of segments with a plurality of DG devices
coupled throughout the segments. In the event that a fault occurs
on a segment, DG devices may contribute to the fault current along
with the substation. This results in a bi-directional fault
current, and traditional relays sensitive to current direction may
not initiate protective actions within predetermined
specifications. Another issue with connection of distributed
generators is that it changes the fault current of the distribution
system. In other words, when you connect a distributed generator to
the distribution system it will contribute to the fault current
based on the power it is generating. This can lead to a failure of
protection systems to detect faults when there are high levels of
distributed generation. Therefore, conventional/traditional
protection schemes/systems can be difficult to coordinate.
BRIEF DESCRIPTION OF THE INVENTION
In one aspect, an electric distribution system is provided. The
electric distribution system includes at least one feeder including
at least one segment including a first end and an opposing second
end. The electric distribution system also includes a protection
and control system that includes at least one protective device
coupled to the at least one segment proximate each of the first end
and the opposing second end. The protection and control system also
includes at least one electric current measuring device coupled to
the at least one segment proximate each of the first end and the
opposing second end. The protection and control system further
includes a processor coupled in communication with the electric
current measuring devices. The processor is programmed to determine
a difference between a synchronized first electric current measured
proximate the first end and a synchronized second electric current
measured proximate the opposing second end. The processor is also
programmed to determine a switching condition of the protective
devices as a function of the difference between the synchronized
first and second electric currents.
In another aspect, a protection system for an electric distribution
system is provided. The electric distribution system includes at
least one feeder that includes at least one segment at least
partially defined by a first end and an opposing second end. The
electric distribution system also includes at least one distributed
generation (DG) device coupled to the electric distribution system.
The protection system includes at least one protective device
coupled to the at least one segment proximate each of the first end
and the opposing second end. The protection system also includes at
least one electric current measuring device coupled to the at least
one segment proximate each of the first end and the opposing second
end. The protection system further includes a processor coupled in
communication with the electric current measuring devices. The
processor is programmed to determine a difference between a
synchronized first electric current measured proximate the first
end and a synchronized second electric current measured proximate
the opposing second end. The processor is also programmed to
determine a switching condition of the protective devices as a
function of the difference between the synchronized first and
second electric currents.
In yet another aspect, a method of assembling an electric
distribution system is provided. The method includes providing at
least one feeder including at least one segment. The at least one
segment includes a first end and an opposing second end. The method
also includes coupling at least one protective device to the at
least one segment proximate each of the first end and the opposing
second end. The method further includes coupling at least one
electric current measuring device to the at least one segment
proximate each of the first end and the opposing second end. The
method also includes coupling a protection and control system to
each of the electric current measuring devices. The method further
includes configuring the protection and control system to determine
a difference between a first electric current measured proximate
the first end and a second electric current measured proximate the
opposing second end. The method further includes configuring the
protection and control system to determine a priority of switching
of the protective devices as a function of the difference between
the first and second electric currents.
BRIEF DESCRIPTION OF THE DRAWINGS
These and other features, aspects, and advantages of the present
invention will become better understood when the following detailed
description is read with reference to the accompanying drawings in
which like characters represent like parts throughout the drawings,
wherein:
FIG. 1A is a schematic diagram of a typical conventional prior art
radial distribution feeder circuit;
FIG. 1B is a graphical view, i.e., a graph of electric currents as
a function of distributed generation penetration;
FIG. 2 is a block diagram of an exemplary computing device that may
be used to monitor and/or control the operation of a portion of an
electric distribution system;
FIG. 3 is block diagram of an exemplary electric distribution
protection and control system that includes an electric
distribution system controller;
FIG. 4 is a schematic diagram of an exemplary electric distribution
system and one feeder thereof;
FIG. 5 is a schematic diagram of a portion of the electric
distribution system and the protection and control system shown in
FIGS. 3 and 3;
FIG. 6 is a flowchart of an exemplary method of assembling the
electric distribution system shown in FIGS. 3, 4, and 5; and
FIG. 7 is a continuation of the flowchart in FIG. 6
Unless otherwise indicated, the drawings provided herein are meant
to illustrate key inventive features of the invention. These key
inventive features are believed to be applicable in a wide variety
of systems comprising one or more embodiments of the invention. As
such, the drawings are not meant to include all conventional
features known by those of ordinary skill in the art to be required
for the practice of the invention.
DETAILED DESCRIPTION OF THE INVENTION
In the following specification and the claims, reference will be
made to a number of terms, which shall be defined to have the
following meanings.
The singular forms "a", "an", and "the" include plural references
unless the context clearly dictates otherwise.
"Optional" or "optionally" means that the subsequently described
event or circumstance may or may not occur, and that the
description includes instances where the event occurs and instances
where it does not.
Approximating language, as used herein throughout the specification
and claims, may be applied to modify any quantitative
representation that could permissibly vary without resulting in a
change in the basic function to which it is related. Accordingly, a
value modified by a term or terms, such as "about" and
"substantially", are not to be limited to the precise value
specified. In at least some instances, the approximating language
may correspond to the precision of an instrument for measuring the
value. Here and throughout the specification and claims, range
limitations may be combined and/or interchanged, such ranges are
identified and include all the sub-ranges contained therein unless
context or language indicates otherwise.
FIG. 1A is a schematic diagram of a typical conventional prior art
radial distribution feeder circuit 10. Feeder circuit 10 is coupled
to a portion of an electric power grid 11 that supplies electric
power to a transmission and distribution substation 12. Electric
power from substation 12 is then fed to various loads (not shown)
through a feeder 17 including a plurality of power circuit breakers
and/or recloser devices 14. Feeder 17 is divided into a plurality
of protection zones 16 that are at least partially defines by
breakers/devices 14 and electrical measurement devices 18 that
include current transformers and voltage transformers.
Breakers/devices 14 may be operated by an instantaneous and time
overcurrent protection device such as an overcurrent relay (not
shown) used to facilitate fault detection. In some embodiments,
there may be multiple other overcurrent protection devices along
radial distribution feeder circuit 10 that are time coordinated so
that the device closest to the fault will trip the fastest. Also,
in some embodiments, if a timed overcurrent scheme is applied, the
settings of the overcurrent relay are such that for higher fault
currents, the relay trips the recloser earlier as compared to lower
fault currents. A distributed generator (DG) 22 may also be
connected to feeder circuit 10. For illustrative purposes, a fault
25 is shown occurring on feeder circuit 10 within protection zone
16 downstream of DG 22.
FIG. 1B is a graphical view, i.e., a graph 50 of electric currents
as a function of distributed generation penetration. Graph 50
includes a y-axis 52 that represents per-unit (pu) values of the
current rating of feeder 17 (shown in FIG. 1A) extending from 1.0
pu to 3.5 pu in increments of 0.5 pu. Graph 50 also includes an
x-axis 54 that represents the penetration level of DGs 22 (shown in
FIG. 1A) extending from 0.0 to 1.0 in increments of 0.2. As used
herein, the term "penetration level" refers to the ratio of the
amount of DG-generated electric power injected into feeder 17 to
the capacity of feeder 17, wherein the units of penetration level
are dimensionless.
Referring to FIGS. 1A and 1B together, fault 25 occurs as shown in
FIG. 1A. Since DG 22 is coupled to feeder 17 downstream of the
overcurrent relay associated with breaker/device 14, and assuming
DG 22 is generating and transmitting electric current into feeder
17, the overcurrent relay will sense a current value lower than the
value associated with fault 25. For illustration, in FIG. 1B, a
first curve 56 shows the fault current as sensed by the overcurrent
relay without the current injected by DG 22. Therefore, first curve
56 is substantially constant with respect to penetration level. A
second curve 58 shows the fault current as sensed by the
overcurrent relay with the current injected by DG 22 increasing
with penetration level. Therefore, the actual fault current sensed
by the feeder relay decreases as the penetration level increases.
Generally, when an overcurrent relay senses a smaller current than
the actual fault current that is being fed at least partially by DG
devices, a delay in response by the overcurrent relay may result,
an effect sometimes referred to as "blinding of protection."
A third curve 60 in FIG. 1B shows the differential current values
when electric current is measured at electrical measurement devices
18 at each end of protection zone 16. As the penetration levels of
DG 22 increase, the differential current values increase as well.
Therefore, while the overcurrent relay may sense a decreasing
current as a function of increasing penetration levels of DG 22,
differential current values maintain a high value and even increase
with penetration level, thereby providing a measureable
characteristic of feeder 17 having a good sensitivity.
Thus, the exemplary systems and methods described herein overcome
disadvantages of known protection and control systems for electric
distribution systems with distributed generation by determining a
current differential between two ends of a feeder segment using
precisely synchronized current measurements. Specifically, the
protection and control systems only respond directly to differences
in the currents entering and leaving the associated segment and
provides bi-directional fault current sensing that is
synchrophasor-based. Therefore, such protection and control systems
are substantially insensitive to changes in fault current levels
and load flow changes due to distributed generation devices coupled
to the distribution system. However, such protection and control
systems are sensitive to different fault impedances. Also, such
protection and control systems identify affected segments quickly
and accurately, and therefore facilitate an improved probability of
operating the protective device that will most likely clear the
fault while reducing electric power disruptions. Such operational
discrimination of the associated reclosers decreases
miscoordination of reclosers, fuses, and other protective devices.
Moreover, by extending segmented protection and control on a
segment-by-segment basis across the feeders, such protection and
control systems facilitate wide-area differential protection across
large portions of an electric distribution system.
Also, the exemplary systems and methods described herein overcome
disadvantages of known protection and control systems for electric
distribution systems with distributed generation by providing
reliable primary and backup protection and control, even for
constantly changing system configurations under high-penetration
scenarios for distributed generation. Furthermore, such protection
and control systems are scalable to include future expansions of
the electric distribution system and additional penetration of
distributed generation. Also, since the systems substantially rely
on differential current determinations, they are substantially
independent of distribution system voltages during weak grid
conditions. Furthermore, such system reduces the potential effects
of induction motor and transformer backfeeding into the feeder
segments, thereby decreasing a potential for inadvertent operation
of affected reclosers.
FIG. 2 is a block diagram of an exemplary computing device 105 that
may be used to monitor and/or control the operation of a portion of
an electric distribution system (not shown in FIG. 2). Computing
device 105 includes a memory device 110 and a processor 115
operatively coupled to memory device 110 for executing
instructions. Processor 115 may include one or more processing
units (e.g., in a multi-core configuration). In some embodiments,
executable instructions are stored in memory device 110. Computing
device 105 is configurable to perform one or more operations
described herein by programming processor 115. For example,
processor 115 may be programmed by encoding an operation as one or
more executable instructions and providing the executable
instructions in memory device 110.
In the exemplary embodiment, memory device 110 is one or more
devices that enable storage and retrieval of information such as
executable instructions and/or other data. Memory device 110 may
include one or more computer readable media, such as, without
limitation, random access memory (RAM), dynamic random access
memory (DRAM), static random access memory (SRAM), a solid state
disk, a hard disk, read-only memory (ROM), erasable programmable
ROM (EPROM), electrically erasable programmable ROM (EEPROM),
and/or non-volatile RAM (NVRAM) memory. The above memory types are
exemplary only, and are thus not limiting as to the types of memory
usable for storage of a computer program.
Further, as used herein, the terms "software" and "firmware" are
interchangeable, and include any computer program stored in memory
for execution by personal computers, workstations, clients and
servers.
FIG. 3 is block diagram of an exemplary protection and control
system 200 that may be used to monitor and/or operate at least a
portion of an electric distribution system 205. In the exemplary
embodiment, system 200 includes a substation-level centralized
protection and control system controller 215 that may be coupled to
other devices 220 with a communication network 225. Therefore,
alternatively, rather than a centralized topology, system 200 may
include a decentralized, i.e., a distributed control topology.
Embodiments of network 225 may include operative coupling with,
without limitation, the Internet, a local area network (LAN), a
wide area network (WAN), a wireless LAN (WLAN), and/or a virtual
private network (VPN). While certain operations are described below
with respect to particular computing devices 105, it is
contemplated that any computing device 105 may perform one or more
of the described operations. For example, controller 215 may
perform all of the operations below.
Referring to FIGS. 2 and 3, controller 215 is a computing device
105. In the exemplary embodiment, computing device 105 is coupled
to network 225. In an alternative embodiment, controller 215 is
integrated with other devices 220. In one embodiment, controller
215 interacts directly with a first operator 230 and/or a second
operator 235 through communications network 225 and/or other
devices 220. In the exemplary embodiment, protection and control
system 200 includes one or more monitoring sensors 240. Monitoring
sensors 240 collect operational measurements including, without
limitation, substation voltage and current readings, localized
voltage and current readings throughout electric distribution
system 205, and/or any other type of data. Monitoring sensors 240
repeatedly (e.g., periodically, continuously, and/or upon request)
transmit operational measurement readings at the time of
measurement. Controller 215 receives and processes the operational
measurement readings. Also, controller 215 includes, without
limitation, sufficient data, algorithms, and commands to facilitate
centralized protection and control of electric distribution system
205 (discussed further below).
FIG. 4 is a schematic diagram of exemplary electric distribution
system 205 and one feeder F1 thereof. In the exemplary embodiment,
electric distribution system 205 is a 60 Hertz (Hz) system as can
be found throughout North America. Alternatively, electric
distribution system 205 may be a 50 Hz system as may be found in
regions of Europe. Also, alternatively, electric distribution
system 205 may have any topology that enables operation of
distribution system 205 as described herein, including, without
limitation, a radial topology, a ring topology, and a mesh
topology.
Electric distribution system 205 includes a substation 300 coupled
to a larger portion of electric power grid 301. Substation 300
includes a step-down substation transformer 302 that defines a high
side bus 304 and a low side bus 306. Transformer 302 transforms
high side bus 304 voltage to low side bus 306 voltage within a
defined range. Electric distribution system 205 includes a
plurality of electric distribution sections, or feeders F1, F2, and
F3, discussed further below.
In the exemplary embodiment, feeder F1 is coupled to transformer
302. Feeders F2 and F3 show how additional, similar feeders are
coupled to transformer 302. Further, feeder F1 includes at least
one electric power isolation device 305. Feeder F1 is divided into
serialized segments S, e.g., a first segment S1, a second segment
S2, and X segments SX in series, wherein X is any integer that
enables operation of feeder F1 as described herein. Isolation
devices 305 disconnect one section from another section, and
include, without limitation, reclosers, circuit breakers, and fuses
and their respective relays. Such segmentation at least partially
defines a plurality of buses B, i.e., a first bus B1 coupled to
segments S1 and S2 and an X Bus coupled to segments SX.
Electric distribution system 205 includes a plurality of
distribution transformers 312 (only one shown). Electric
distribution system 205 also includes a plurality of electric loads
314 (only one shown) coupled to each of distribution transformers
312. Distribution transformers 312 and electric loads 314 may be
coupled to each of buses B1 through BX. In another embodiment, the
distribution transformers 312 and loads 314 may also be tapped from
feeder F1 directly rather than connecting them at the bus. Electric
distribution system 205 further includes a plurality of distributed
generation (DG) devices, e.g., a first DG device DG1 coupled to
first bus B1 and an X DG device DGX coupled to bus BX. Distributed
generation devices DG1 through DGX inject electric power into
electric distribution system 205. Electric distribution system 205
includes any number of buses B1 through BX, any number of
distribution transformers 312 and loads 314, and any number of
distributed generation devices DG1 through DGX.
Protection and control system 200 includes sufficient computing
resources and programming to facilitate operation of protection and
control of electric distribution system 205 (discussed further
below). The protection and control system 200 may be a centralized
system located at a substation or any other appropriate location as
shown in FIG. 4 or it may also be a decentralized system where each
of the isolation devices 305 have its own control circuit. System
200 is coupled in communication with equipment within substation
300 and feeder F1 via a plurality of communication devices 308
(only two labeled) that may define a portion of communication
network 225. Communication network 225 may also include a remote
communications device, e.g., a remote terminal unit (RTU) 310 that
facilitates remote communication between system 200 and
communication devices 308.
FIG. 5 is a schematic diagram of a portion of electric distribution
system 205 and protection and control system 200. Feeders F1, F2,
and F3 are coupled to substation 300 via electric power isolation
devices 305, i.e., a first recloser R1, a second recloser R2, and a
third recloser R3, respectively. As used herein, the terms
"electric power isolation device" and "recloser" include the
associated protective relays (not shown for clarity). Also, as used
herein, the term "switching condition" of protective devices, e.g.,
reclosers refers to whether the protective device is "ON/CLOSED" or
"OFF/OPEN". Feeder F1 is divided into serialized first segment S1,
second segment S2, and X segments SX in series, wherein X is any
integer that enables operation of feeder F1 as described herein.
First bus B1 is coupled to segments S1 and S2, and a first
photovoltaic distributed generation device PV-DG1 and a
distribution transformer 312 with its associated electric loads 314
are coupled to first bus B1. Alternatively, any type of distributed
generation device is coupled to first bus B1, including, without
limitation, fossil fuel-fired generators and microturbines. A
fourth recloser R4 is coupled to first segment S1 and first bus B1,
a fifth recloser R5 is coupled to first bus B1 and second segment
S2, and a sixth recloser R6 is coupled to segment S2 and X segments
SX. Further, in one embodiment, distribution transformer 312 with
its associated electric loads 314 may be directly tapped from
feeder F1. Feeder F1 may include any number of buses B1 through BX,
any number of distribution transformers 312 and loads 314, and any
number of distributed generation devices such as photovoltaic
distributed generation devices PV-DG1.
Similarly, feeder F2 is divided into a serialized third segment S3
and Y segments SY in series, wherein Y is any integer that enables
operation of feeder F2 as described herein. A second bus B2 is
coupled to segments S3 and SY, and second bus B2 is coupled to a
plurality of electric loads 314 (only one shown) and each of
associated distribution transformers 312 and a second photovoltaic
distributed generation device PV-DG2. A seventh recloser R7 is
coupled to third segment S3 and second bus B2. A third photovoltaic
distributed generation device PV-DG3 is coupled to substation 300
on low side bus 306 between second feeder F2 and third feeder
F3.
Also, in the exemplary embodiment, protection and control system
200 includes one or more monitoring sensors 240. The monitoring
sensors may be synchronized phasor measurement devices
(synchrophasors), e.g., a phasor measurement unit (PMU) 350 (shown
in phantom). Alternatively, any combination of electrical devices
that measures current and/or voltage, and/or generates and
transmits synchronized current and/or voltage phasor measurement
signals that enables operation of protection and control system 200
as described herein is used. In general, monitoring sensors measure
provide phasor information (both magnitude and phase angle) of
electrical signals according to a global time signal.
In the embodiment shown, first segment S1 includes a first end 320
that includes a first set of current transformers CT1 for measuring
electric current at first recloser R1. First segment S1 also
includes an opposing, second end 322 that includes a second set of
current transformers CT2 for measuring electric current at fourth
recloser R4. Therefore, current transformers CT1 and CT2 measure
the total electric current entering as well as leaving first
segment S1. Current transformers CT1 and CT2 repeatedly (e.g.,
periodically, continuously, and/or upon request) measure and
transmit electric current readings "real-time." As used herein, in
the context of measurement signal transmission, the term
"real-time" refers to a substantially instantaneous receipt of a
measurement signal from the time of generation and transmission of
such signal.
Further, in the exemplary embodiment, current transformers CT1 and
CT2 are each coupled to controller 215 via an intelligent
electronic device (IED) 323 which may also have a voltage sensor
(not shown) connected to it. Reclosers R1 and R4, current
transformers CT1 and CT2, IEDs 323 (or PMUs 350) in conjunction
with controller 215, at least partially define a first differential
protection zone 400. Further, in at least some embodiments, a
single controller (not shown) for each individual relay (not shown)
may be used at the location of each associated recloser R1 through
R7, thereby defining a distributed topology for protection and
control system 200. IEDs 323 (or PMUs 350) generate and transmit
voltage and current phasor signals that are substantially
synchronized and time-stamped.
Controller 215 receives and processes the synchronized current
phasor measurements from current transformers CT1 and CT2 via IEDs
323 (or PMUs 350) and communications network 225. In other
embodiments, where distributed generators or transformers/loads are
directly tapped from feeder, a current supplied by distributed
generator to the feeder and current absorbed by transformer/load
may also be transmitted to controller 215. Controller 215 includes,
without limitation, sufficient data, algorithms, and commands to
facilitate protection and control of electric distribution system
205 via reclosers R1 and R4. Specifically, controller 215 includes
sufficient programming to determine a total current differential
across first segment S1 and to initiate operation of reclosers R1
and R4 as necessary to facilitate clearing faults on portions of
electric distribution system 205.
Similarly, second segment S2 includes a first end 324 and an
opposing second end 326. Second segment's S2 reclosers R5 and R6, a
pair of current transformers CT3 and CT4, and IEDs 323 (or PMUs
350), in conjunction with controller 215, at least partially define
a second differential protection zone 410. Controller 215 receives
and processes the synchronized current phasor measurements from
current transformers CT3 and CT4 via IEDs 323 (or PMUs 350).
Controller 215 then again includes sufficient programming to
determine a total current differential across second segment S2 and
to initiate operation of reclosers R5 and R6 to facilitate clearing
faults on portions of electric distribution system 205.
Third segment S3 includes a first end 328 and an opposing second
end 330. Third segment's S3 reclosers R2 and R7, a pair of current
transformers CT5 and CT6, IEDs 323 (or PMUs 350), in conjunction
with controller 215, at least partially define a third differential
protection zone 420. Controller 215 receives and processes the
synchronized current phasor measurements from potential
transformers PT5 and PT6 via IEDs 323 (or PMUs 350). Further,
controller 215 includes sufficient programming to determine a total
current differential across third segment S3 and to initiate
operation of reclosers R2 and R7 as necessary to facilitate
clearing faults on portions of electric distribution system
205.
In addition to the exemplary embodiments described above,
alternative embodiments may include a plurality of distributed
controllers that include, without limitation, sufficient data,
algorithms, and commands to facilitate distributed protection and
control of electric distribution system 205 via the reclosers.
In general, protection and control system 200 uses a PMU-based
differential protection scheme to determine a total current
differential between the two ends of a segment using precisely
synchronized current measurements. The current flowing in and the
current flowing out of a segment is measured and a predetermined
mismatch of the current in and out values indicate the existence of
a fault on electric distribution system 205. The predetermined
mismatch may be a threshold value, e.g., without limitation, if
incoming current to a segment is labeled as I.sub.IN and outgoing
current from the segments is labeled as I.sub.OUT, and the
differential value between I.sub.N and I.sub.OUT=0, no fault is
determined to exist by system 200. However, if the differential
value between I.sub.N and I.sub.OUT.gtoreq.a predetermined
threshold value, a fault is determined to exist between the
associated reclosers that may both be opened to clear the fault.
Furthermore, if some distributed generators or transformer/loads
are tapped from the feeder directly, the threshold value may be
based on the current supplied or absorbed by the distributed
generators and transformer/loads.
For example, in the event of a fault 430 that is generated on
segment S3, an inrush of electric current will be sensed by PMUs
350 within third differential protection zone 420. In one
embodiment, within a three-cycle communications latency period,
PMUs 350 sense an inrush of currents 440 and 450, respectively.
Also, within that three cycles, PMUs 350 generate and transmit
synchronized current signals proportional to current inrushes 440
and 450, respectively.
Current inrush 440 includes electric current supplied from
substation 300 and additional current supplied from photovoltaic
device PV-DG3. Some current may also be supplied to current inrush
440 via photovoltaic device PV-DG1 and first segment S1. Current
inrush 450 includes electric current supplied from segment(s) SY
and additional current supplied from photovoltaic device PV-DG2,
wherein current inrush 450 is in the opposite direction of typical
current flow. Therefore, a fault current 460 is bi-directional.
Controller 215 includes, without limitation, sufficient data,
algorithms, and commands to determine a real-time total current
differential associated with segment S3. If the determined electric
current differential value is greater than a predetermined
setpoint, i.e., threshold value, protective functions are commanded
by controller 215, and, in the present example, reclosers R2 and R7
open.
In operation, for alternative fault scenarios, for example, a fault
470 positioned on bus B1, current from substation 300 through
segment S1 and bus B1 are substantially instantaneously increased.
However, photovoltaic device PV-DG1 contributes to the fault
current (not shown) such that the current sensed by current
transformer CT2 will not be the full fault current. Protection and
control system 200 responds directly to the difference of
synchronized currents sensed by current transformers CT1 and CT2
coupled to segment S1 and the difference of synchronized currents
sensed by current transformers CT3 and CT4 coupled to segment S2.
However, when the fault is on bus B1, then protection and control
system 200 responds to a difference of synchronized currents sensed
by current transformers CT2 and CT3. The increase in current
through current transformer CT2 is much greater than the change in
current through current transformer CT3, and controller 215
includes, without limitation, sufficient data, algorithms, and
commands to determine that fault 470 does not reside on segments S1
and S2, and through the process of elimination, must reside on bus
B1. Therefore, recloser R4, and possibly recloser R5, will be
commanded to open and then reclose to clear fault 470, and the
"blinding of protection" deficiency as described earlier will not
prevent prompt fault clearing with a reduction of collateral
interruption to system customers.
Further, in operation, some of electric loads 314 may include large
induction motors that may generate a backfed electric current into
the segment they are coupled to. Such backfeeding typically only
lasts approximately three cycles prior to dying out and is
typically relatively small, wherein the magnitude of the backfed
current will vary inversely to the associated terminal voltage.
Moreover, protection and control system 200 determines a current
differential between the two ends of a segment using precisely
synchronized current measurements. As such, the small amount of
backfed current entering the segment coupled to the motors and the
directly adjacent segments only marginally affects the differential
current determination for those segments, and only for
approximately three cycles prior to dying out. Therefore, reducing
the potential effects of induction motor backfeeding into the
feeder segments decreases a potential for inadvertent operation of
affected reclosers.
Similarly, in operation, some of distribution transformers 312 may
induce a backfed inrush of current that may have a magnitude
approximately ten times greater than normal operating current, such
current magnitude at least partially dependent upon the voltage of
the segment that transformer 312 is coupled to. Such backfeeding
typically only lasts approximately one to three seconds prior to
decreasing to normal levels. Moreover, protection and control
system 200 determines a current differential between the two ends
of a segment using precisely synchronized current measurements. As
such, the backfed current entering the segment coupled to the
transformers 312 only marginally affects the differential current
determination for that segment, and only for approximately one to
three seconds prior to decreasing to normal levels. Therefore,
reducing the potential effects of transformer backfeeding into the
feeder segments decreases a potential for inadvertent operation of
affected reclosers.
Further, in operation, protection and control system 200 determines
a current differential between the two ends of a segment using
precisely synchronized current measurements, and responds directly
to changes in the currents entering and leaving the associated
segment. Therefore, system 200 is substantially insensitive to
changes in fault current levels and load flow changes.
FIG. 6 is a flowchart of an exemplary method 500 of assembling
electric distribution system 205 (shown in FIGS. 3, 4, and 5). In
the exemplary embodiment, at least one feeder F1/F2/F3 (shown in
FIGS. 4 and 5) including at least one segment S1/S2/S3 (shown in
FIG. 5) is provided 502, wherein segment S1/S2/S3 includes a first
end 320/324/328 (shown in FIG. 5) and an opposing second end
322/326/330 (shown in FIG. 5). In on embodiment, distributed
generation device DG1/DG2 (shown in FIG. 4) and
PV-DG1/PV-DG2/PV-DG3 (shown in FIG. 5) may be coupled 504 to a
portion of electric distribution system 205. A plurality of
protective devices R1/R2/R3/R4/R5/R6/R7 (shown in FIG. 5) are
coupled 506 to segment S1/S2/S3. Specifically, a first protective
device R1/R2/R3/R5 is coupled 508 to segment S1/S2/S3 proximate to
first end 320/324/328, respectively, and a second protective device
R4/R6/R7 is coupled 510 to segment S1/S2/S3 positioned proximate to
opposing second end 322/326/330, respectively.
Also, in the exemplary embodiment, a plurality of synchronized
electric current measuring devices 240/CT1/CT2/CT3/CT4/CT5/CT6 or
PMUs 350 (all shown in FIG. 5) are coupled 512 to segment S1/S2/S3
proximate to each of first end 320/324/328 and opposing second end
322/326/330. In one embodiment, IED 323 is coupled 514 to each of
electric current measuring devices 240/CT1/CT2/CT3/CT4/CT5/CT6.
FIG. 7 is a continuation of the flowchart started in FIG. 6.
Further, in the exemplary embodiment, protection and control system
200 is configured 522 to determine a difference between a first
electric current measurement made proximate to first end
320/324/328 and a second electric current measurement made
proximate to opposing second end 322/326/330, wherein the first
electric current measurement and the second electric current
measurement are substantially temporally synchronized. Protection
and control system 200 is also configured 524 to determine a
switching condition of protective devices R1/R2/R3/R4/R5/R6/R7 as a
function of the difference between the first and second electric
currents.
The above-described described protection and control system for an
electric distribution system with distributed generation provides a
cost-effective method for increasing electric power reliability and
decreasing power disruptions. Specifically, the devices, systems,
and methods described herein determine a current differential
between two ends of a feeder segment using precisely synchronized
current measurements generated by PMUs. More specifically, the
devices and systems described herein only respond directly to
differences in the currents entering and leaving the associated
segment and provide bi-directional fault current sensing that is
synchrophasor-based. Therefore, the devices and systems described
herein are substantially insensitive to changes in fault current
levels and load flow changes due to distributed generation devices
coupled to the distribution system, while remaining sensitive to
different fault impedances. Also, the devices, systems, and methods
described herein identify affected segments quickly and accurately,
and therefore facilitate an improved probability of operating the
protective device that will most likely clear the fault while
reducing electric power disruptions. Such operational
discrimination of the associated reclosers decreases
miscoordination of reclosers, fuses, and other protective devices.
Moreover, the devices, systems, and methods described herein extend
segmented protection and control on a segment-by-segment basis
across the feeders, such protection and control system facilitating
wide-area differential protection across large portions of an
electric distribution system.
Also, the devices, systems, and methods described herein provide
reliable primary and backup protection and control, even for
constantly changing system configurations under high-penetration
scenarios for distributed generation. Furthermore, the devices,
systems, and methods described herein are scalable to include
future expansions of the electric distribution system and
additional penetration of distributed generation. Also, since the
systems substantially rely on differential current determinations,
they are substantially independent of distribution system voltages
during weak grid conditions. Furthermore, such systems reduce the
potential effects of induction motor and transformer backfeeding
into the feeder segments, thereby decreasing a potential for
inadvertent operation of affected reclosers.
An exemplary technical effect of the methods, systems, and
apparatus described herein includes at least one of (a) enabling
determination of a current differential between two ends of a
feeder segment using precisely synchronized current measurements;
(b) enabling responses directly to changes in the currents entering
and leaving the associated segment; (c) enabling both (a) and (b)
above while maintaining substantial insensitivity to changes in
fault current levels and load flow changes due to distributed
generation devices coupled to the system; (d) enabling both (a) and
(b) above while maintaining sensitivity sensitive to different
fault impedances; (e) enabling both (a) and (b) above, thereby
enabling bi-directional fault current sensing; (f) facilitating an
improved probability of operating protective devices that will most
likely clear a fault while reducing electric power disruptions; (g)
enabling reliable primary and backup protection and control for
dynamic distribution system configurations; and (h) enabling robust
protection and control independent of distribution system voltages
during weak grid conditions.
Exemplary embodiments of the devices, systems, and methods for
protection and control for an electric distribution system with
distributed generation are described above in detail. The devices,
systems, and methods are not limited to the specific embodiments
described herein, but rather, components of systems and/or steps of
the method may be utilized independently and separately from other
components and/or steps described herein. For example, the systems
and methods may also be used in combination with other protection
and control systems and methods, and are not limited to practice
with only the electric distribution system with distributed
generation as described herein. Rather, the exemplary embodiment
can be implemented and utilized in connection with many other
protection and control systems and applications.
The methods and systems described herein are not limited to the
specific embodiments described herein. For example, components of
each system and/or steps of each method may be used and/or
practiced independently and separately from other components and/or
steps described herein. In addition, each component and/or step may
also be used and/or practiced with other assemblies and
methods.
This written description uses examples to disclose the invention,
including the best mode, and also to enable any person skilled in
the art to practice the invention, including making and using any
devices or systems and performing any incorporated methods. The
patentable scope of the invention is defined by the claims, and may
include other examples that occur to those skilled in the art. Such
other examples are intended to be within the scope of the claims if
they have structural elements that do not differ from the literal
language of the claims, or if they include equivalent structural
elements with insubstantial differences from the literal languages
of the claims.
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